Tuesday, May 15, 2018

Renew an Old Field with a Horizontal Well

Maraven, S.A., one Venezuela's three national oil companies, is going for the hard-to-get roe in Block 1 of lake Maraicabo, Venezuela. Forty years of production there has left isolated pockets of hydrocarbon, known as attic oil, in the tops of structural and stratigraphic traps. Recovering this attic oil with vertical wells is not usually cost-effective because the thin layer of oil in place increases the likelihood of water coning. 

 Taking a new approach, an integrated team of geoscientists from Maraven and Schlumberger planned, drilled and completed VLA-1035 - Lake Maracaibo's first successful horizontal well- gaining an eight-fold increase in oil production over vertical wells in the same reservoir.

 The motivation for VLA-1035 was provided when Maraven's parent company Petroleos de Venezuela, S.A. (PDVSA) launched a development program for Lake Maracaibo. The plan called for generating 11 billion barrels of additional oil reserves through new wells, horizontal development and reworking of older wells. Although horizontal drilling had been considered in Lake Maracaibo since 1986, attempts by other companies to drill horizontal wells were unsuccessful because of the complex geology or completion problems.

Yet, horizontal drilling seemed the only way to produce from Block 1. A vertical well typically produced 150 barrels of oil per day (BOPD). Most older wells had been shut in as uneconomic, and the wells that were on line typically produced no more than 150 barrels of oil. Some recent wells began producing water immeadiately, others made water within two months. Early breakthrough of water was inevitable because of the reduced vertical heigh of pay, reduced reservoir pressure and increased relative permeability of water to oil.

The Planning Stage

In early 1992, Maraven began assessing the economic and tehnical feasibility of drilling a horizontal drainhole to recover remaining reserves.  Reservoir engineers evaluated production histories to identify regions with recoverable oil and later modeled drainhole performance. Geophysicist used three-dimensional (3D) seismic data, having vertical resolution of tens to hundreds of feet, to obtain a big picture of the reservoir and identify prospective sands. Geologist and sedimentologist examined cores and logs, with vertical resolutions on the order of inches to one foot, to identify sands and model their orientation, continuity and distribution. Petrophysicst working with sedimentologist integrated log and core data with drilling records, including bit and mud data, for 33 wells in the area. This provided an understanding of the mechanical stability of the formation, fluid distribution, oil-water contact location, and flagged possible drilling difficulties.

They targeted reservoir VLA-8 in Block 1, bound on the west by the Icotea fault. It contains a region of low dips (2 degree to 10 degree) called El Pilar and a region of high dips (30 degree to 45 degree) called the Attic. Since 1954, VLA-8 has produced 42 million barrels of the estimated 118 million barrels of oil in place. This production reduced reservoir pressure from 3200 psi to 1800 psi at 6700 ft [2040m] in some areas and raised the oil-water contact. 

Water coning has been a problem from the beginning, with the average water cut in the field increasing from 20% in 1960 to 85% by 1991. The influx of water moves hydrocarbons toward the top of traps, creating isolated pockets of oil. Because of the extensive production in the field, normally desirable high permeabiltiy zones had water, whereas low-permeability zones contained oil.

The attic is considered the last opportunity  for development in Block 1. Three-dimensional seismic data, shot in 1990 and covering 235 square km, revealed the structural complexity of the fold and fault systems that bound the reservoir, and also stratigraphic features within the pay sands. The steeply dipping flanks are difficult to image seismically because a mud layer at the bottom of Lake Maracaibo absorbs high-frequency seismic energies.

 Well-tie sections, time slices and 3D cube displays from Schlumberger's Charisma workstation contributed to understanding the structure. Productive sands in the attic are in the C-6 and C-7 horizons, which have each been divided into three intervals-upper, middle and lower. In addition, seismic attribute sections were generated on the workstation and interpreted. Seismic attributes, such as signal phase and polarity, can reveal subtle characteristics of a seismic trace. In this case, instantaneous phase sections were particularly helpful in confirming the continuity of the C-7 structure. But the steep dip of the beds prevented determining an exact location of the C-7 reservoir.

Maraven was especially interested in the massive C-7 sands, 60 to 200 ft thick, products of deltaic and fluvial depositional environments. Target sands appeared to be the C-7 upper and lower interevals, with the initial preference by Maraven for the lower one.

Their next step was putting the seismic, log and core data into a reservoir model that would help identify the drainhole's position in the sand for maximum production. Modeling performace of the proposed horizontal drainhole in the C-7 sands was accomplished with a black-oil reservoir simulator.

 Based on log and core analysis, the model comprised a partially anisotropic reservoir with a horizontal permeability 250 md and a vertical to horizontal permeability ratio, Kv/Kh, of 0.5. In the model , the reservoir was bounded on one side by an aquifer and on the other by the Icotea fault. Assuming that no more vertical wells would be shut in and that water cut would stabilize, Maraven calculated that existing conventional wells would recover only 18% of the remaining reserves.

To find the most productive drainhole location, Maraven modeled performance for four horizontal drainholes, with lengths of 584 ft , 884 ft, 1200 ft and 1600 ft, in the upper, middle and lower sands. The 1200-ft drain-hole in the C-7 lower sands performed best. Overall, reservoir modeling showed that a horizontal well would recover 40% to 160% more oil than a vertical well. 

After analyzing the seismic interpretation and the reservoir simulation, Maraven geoscientist concluded that a horizontal drainhole could not be drilled without additional information from a pilot well. First, they needed to pinpoint the top and thickness of C-7 with respect to the Icotea fault. Second, they needed to better define the oil-water contact. At this point, they negotiated with Schlumberger to manage drilling the pilot well and the subsequent drainhole under Maraven supervision. As Maraven and Schlumberger geoscientist worked together on the project, specialist from both companies refined the initial geologic and reservoir engineering studies.

Coordinating the project was Anadrill's Bill Lesso, who had worked with Schlumberger's Horizontal Integration Team (HIT), which pioneered an integrated-services approach to drilling horizontal wells. The HIT group found that a coordinator was essential to facilitate communication betwen disciplines and act as a catalyst for decision making. 

The program for drilling and completing the horizontal well took about 10 weeks. Each task in the program was listed chronologically with its projected duration and status. This helped identify both progress and problem areas. Once drilling began, these weekly meetings gave way to daily sessions at a "mission control" center in Lagunillas, 20 miles from the offshore rig but linked to it by phone, fax and data transmission lines. Every morning at 9:00, the team met to discuss drilling or completion operations- whatever was planned for the next 48 hours. The team needed to achieve a consensus on drilling decisions and be on call round the clock during critical operations. To keep team members and interested parties informed, the project coordinator prepared and distributed weekly updates - one page summaries that highlighted progress and issues to be resolved.

Prompt and frequent communication was critical for weaving togehter the expertise of Maraven and Schlumberger specialist. 

Drilling the Pilot Hole

The plan called for an 8 1/2- inch pilot hole deviated 55 degree , with three possible drainhole trajectories to follow.  Log data from the pilot well would be used to pick the best drainhole location. In addition to determining the drainhole trajectory, drilling the pilot hole gave the team an opportunity to learn how directional drilling equipment behaved in the VLA-8 formation.

The well was drilled vertically to a kickoff at 5350 ft [1630 m] , then with a build of 6 degree/100 ft to 50 degree deviation using a steerable bottomhole assembly (BHA). CDR compensated Dual Resistivity and CDN compensated Density Neutron measurements were added to correlate in real time with log data from nearby wells. LWD logs were later complemented by a suite of wireline measurements comprising a resistivity log, two porosity logs, a gamma ray log and the DSI Dipole Shear Sonic Imager log. Tool sticking in the build section of the pilot well, attributed to overbalance caused by low reservoir pressure, precluded logging with a dipmeter tool. The lack of dip information near the well created a formidable challenge when it came time to drill the horizontal drainhole.

Log data from the pilot well were fed into the ELAN Elemental Log Analysis progam, which fits openhole log measurements to a formation model comprised of mineral and pore fluid combinations. The ELAN results showed that the C-7 upper sand,  with higher clay content than the other sands, had lowest effective porosity, but the highest hydrocarbon saturations. Logs of the shaly C-7 upper sand indicated oil in the top 40 ft, with a water leg in the clead sand section below. Consequently, the team directed their attention to the C-7 upper rather than lower sand. 

Next, petrophysicst used the impact Integrated Mechanical Properties Analysis Computation Technique program to evaluate whether the C-7 upper sand could support a horizontal drainhole. The Impact program processes a variety of data - including bulk volume analysis from the ELAN output, vertical and horizontal stresses derived from logs and core measurements, and density logs - to calculate the stress field at the borehole wall for a given well inclination and direction. 

More importantly, it establishes safe mud weights along the trajectory in the borehole. The mud-weight range indicates the degree of difficulty and expense associated with drilling a horizontal well.

Vertical stress was derived from log measurements of the cumulative density of overlying sediments. Horizontal stresses were obtained using diferential strain-curve analysis. In this technique, strain gauges are attached to a core sample, which is then encased in a silicone plug and compressed hydrostatically. Hydrostatic compression closes microcracks that developed when the core was removed. Measuring strain while these cracks close gives the ratio of the horizontal stresses.

Analysis of DSI data gave the compressional and shear velocities needed, along with the bulk density, to compute the dynamic elastic moduli. These computations matched the elastic moduli measured on cores prior to strain curve analysis. The Impact analysis showed the zone to be competent and drillable at high angles. 

In finalizing the horizontal trajectory, the team correlated pilot log data with offset data from two nearby wells, which showed that the C-7 upper dipped up about 5 degree from the pilot well, then flattened out and eventually started dipping down. A 6 degree/ 100 feet build to 95 degree was planned to intersect the target sand at 6380 ft true vertical depth (TVD). Markers that could be identified with the LWD gamma ray or resistivity sensors were chosen to verfiy the approach to horizontal.

Drilling the Horizontal Drainhole

The drainhole was geosteered with an LWD system, providing real-time gamma ray and resistivity logs. 



Sunday, May 13, 2018

The State of the Water Base Mud Art

This article will now concentrate on advances in water base mud (WBM) technology by looking at two distinct directions of development: the use of polyols for shale inhibition and the introduction of mixed-metal hydroxides to improve hole cleaning and help reduce formation damage.

Polyol muds-Polyol is the generic name for a wide class of chemicals-including glycerol, polyglicerol or gylcols such as proplylene glycol-that are usually used in conjunction with an encapsulating polymer (PHPA) and inhibitive brine phase (KCl). These materials are nontoxic and pass the environmental protocols, including those laid down in Norway, the UK, The Netherlands, Denmark and the USA.

 Glycols in mud were proposed as lubricants and shale inhibitors as early as the 1960s. But it was not until the late 1980s that the materials became widely considered. Properly engineered polyol muds are robust, highly inhibitive and often cost-effective. Compared with other WBM systems, low volumes are typically required. Polyols have a number of different effects, such as lubricating the drillstring, opoosing bit balling (where clays adhere to the bit) and improving fluid loss. Today, it is their shale-inhibiting properties that attract most attention. For example, test carried out by BP show that the addition of 3 to 5% by volume of polyglycol to a KCl-PHPA mud dramatically improves shale stabilization. 

Field experience using polyol muds has shown improved wellbore stability and yielded cuttings that are harder and drier than those usually associated with WBM.  

Mixed-metal hydroxide (MMH) mud - MMH mud has a low environmental impact and has been used extensively around the world in many situations: horizontal and short-radius wells, unconsolidated or depleted sandstone, high-temperature, unstable shales, and wells with severe lost circulation. Its principal benefit is excellent hole-cleaning properties.

Many new mud systems-including polyol muds -are extensions of existing fluids, with perhaps a few improved chemicals  added. However, MMH mud is a complete departure from existing technology. It is based on an insoluble inorganic, cyrstalline compound containing two or more metals in a hydroxide lattice-usually mixed alumunium/magnesium hydroxide, which is oxygen-deficient. When added to prehydrated bentonite, the positively charged MM particles interact with the negatively charged clays forming a strong complex that behaves like an elastic solid when at rest. 

This gives the fluid its unusual rheology: an exceptionally low plastic viscosity-yield point ratio. Conventional muds with high gel strength usually require high energy to initiate circulation, generating pressure surges in the annulus once flow has been established. Although MM has great gel strength at rest , the structure is easily broken. So it can be transformed into a low-viscosity fluid that does not induce significant friction losses during circulation and gives good hole cleaning at low pump rates even in high-angle wells. 

Selecting a reliable chemical formulation for the drilling fluid so that it exhibits the required properties is one part of the job. Maintaining these properties during drilling is another. 

Circulation of drilling fluid may be considered a chemical process with the wellbore acting as a reactor vessel. In this reactor, the composition of the drilling fluid will be changed dynamically by such factors as filtration at the wellbore and evaporation at the surface; solids will be added and taken away by the drilling process and the solids-control equipment; chemicals will be lost as they adhere to the borehole wall and to cuttings, aand they will be added routinely at the surface, formation fluids will contaminate the mud, perhaps causing flocculation or loss of viscosity and oxygen may become entrained.

Under these circumstances effective management is not trivial. Nevertheless, basic process control techniques have been applied rigside for some years to aid in the selection and maintenance of the fluid formulation and to optimize the solids-control equipment - such as shale shakers and centrifuges. This approach is often linked to incentive contracts, where savings in mud costs are shared between contractor and operator, and has led to remarkable savings in mud cost.

For example, with a systems approach to drilling fluid management for 16 wells offshore Dubai, mud costs were cut in half and reduced as a proportion of total drilling costs from 6% to 3%. At the same time, hole condition remained the same or better - this was assessed by looking at hole diameter, time to run casing and mud usage per foot of well drilled. 

Such an approach is based on three premises:
  • More frequent and more precise measurements, for example five mud checks per day and the introduction of advanced measurement techniques.
  • Efficient data management using mass balance techniques - which track the volumes of chemicals, hole and cuttings- and computerized data storage and acquisition.
  • Integration of the management of the solids control equipment with that of the drilling fluids.

Solid-control efficiency-the percentage of drilled solids removed versus the total amount drilled- is central to drilling efficiency and is a function of the surface equipment, drilling parameters and mud properties. For example, muds that have a lower tendency to hydrate or disperse drilled cuttings generally give higher solids-control efficiency.  

The significance of solids control is that penetration rate is closely linked to the volume of solids in the fluid. The greater the amount of solids, the slower the rate of drilling.  Mud solids are divided into two categories: high-gravity solids (HGS) comprising the weighting agent, usually barite; and low-gravity solids (LGS) made up from clays, polymers and bridging materials deliberately put in the mud, plus drilled solids from dispersed cuttings and ground rock.

The volume of HGS should be maximized, so that the total volume of solids in the mud is minimized, while still achieving the density required to control formation pressures. Therefore, drilled solids must be removed by the solids-control equipment. Howeer, some solids become dispersed as fine particles that cannot be removedd effectively. In this case, the fluid must be diluted with fresh mud containing no drilled solids.

But desirable properties are not always optimum ones. For instance, zero drilled solids at the bit is desirable. However, achieving zero drilled solids would increase mud costs dramatically. It is the job of mud management to plot the optimum course. To do this successfully requires accurate and regular input data.

Traditional field practice is to measure mud density and viscosity ( using a Marsh funnel) about every 30 minutes at both the return line and the suction pit. Other properties- such as rheology, mud solids, fluid loss, oil/water ratio (for OBM), pH, cation exchange capacity, and titrations for chloride and calcium- are measured once every 8 or 12 hours ( depending on drilling conditions) using 1-liter samples taken from the flowline or the active pit. These determinations are then used as a basis for mud treatment until the next set of measurement is made.

To gain better control over the mud system, a more meaningful monitoring strategy may be required. Simply increasing the frequency of traditional measuring techniques to at least five times a day and making sampling more representative of the whole mud system has improved control and significantly reduced the amount of chemicals used to drill a well.  

Mud solids monitor- A common indicator describing the solids content in the mud is the LGS-HGS volume ratio. This is traditionally measured using the retort,a technique that requires good operator skills, takes at least 45 minutes and often has an error margin of more than 15%.


Friday, May 4, 2018

Designing and Managing Drilling Fluid (2)

Shale instability is largely driven by changes in stress and chemical alteration caused by the infiltration of mud filtrate containing water. Over the years, ways have been sought to limit interaction between mud filtrate and water-sensitive formations. So, for example, in the late 1960s, studies of mud-shale reactions resulted in the introduction of a water-base mud (WBM) that combines potassium chloride (KCl) with a polymer called partially-hydrolyzed polyacrylamide-KCl-PHPA mud. PHPA helps stabilize shale by coating it with a protective layer of polymer-the role of KCl will be discussed later.

The introduction of KCl-PHPA mud reduced the frequency and severity of shale instability problems so that deviated wells in highly water-reactive formations could be drilled, although often still at a high cost and with considerable difficulty. Since then, there have been numerous variations on this theme as well as other types of WBM aimed at inhibiting shale. 

However, in the 1970s, the industry turned increasingly towards oil-base mud (OBM) as a means of controlling reactive shale.  Today, OBM not only provides excellent wellbore stability but also good lubrication, temperature stability, a reduced risk of diffrential sticking and low formation damage potential. OBM has been invaluable in the economic development of many oil and gas reserves.

 The use of OBM would probably have continued to expand through the late 1980s and into the 1990s but for the realization that, even with low-toxicity mineral base-oil, the disposal of OBM cuttings can have a lasting environmental impact. In many areas this awareness led to legislation prohibiting or limiting the discharge of these wastes.

To develop alternative nontoxic muds that match the performance of OBM requires an understanding of the reactions that occur between complex, often poorly characterized mud systems and equally complex, highly variable shale formations.

Requisites for a Successful Drilling Fluid

Most OBM is an invert emulsion comprising droplets of aqueous fluid surrounded by oil, which forms the continuous phase. A layer of surfactant on the surface of the water droplet acts like a semipermeable membrane, separating the aqueous solution in the mud from the formation and its water. Water will pass through this membrane from the solution with the lowest concentration of a salt to one with the highest-osmosis.

A key method of maintaining shale stability using OBM is to ensure that the ionic concentration of the salts in the aqueous-internal-phase of the mud is sufficiently high, so that the chemical potential of the water in the mud is equal or lower than that of the formation water in the shale. When both solutions have the same chemical potential, water will not move, leaving the shale unchanged. If the water in the internal phase of the mud has a lower chemical potential than the fluid in the formation, water will travel from the shale to the mud, drying out the rock. Unless dehydration is excessive, this drying out usually leaves the wellbore in good condition.

In WBM, there have been many efforts to protect a water-sensitive formation from mud filtrate. One technique is to introduce a buffer in the form of blocking and plastering agents, ranging from starches and celluloses, through polyacrylamides to asphalts and gilsonites. Total control cannot be achieved in this way so specific inhibiting cations- chiefly potassium and calcium ions -are traditionally added to the base water to inhibit the clay from dispersing-to stop it from breaking up when attacked by aqueous solution. This is achieved by providing cation exchange with the clays in the shale the K+ or Ca2+ commonly replace the sodium ion (Na+) associated with the clay in the shale, creating a more stable rock that is better able to resist hydration. Hence KCl-PHPA fluids.

The movement of WBM filtrate from the wellbore into the surrounding shale is controlled by the difference between the chemical potentials of the various species in the mud, and the corresponding chemical potentials within the formation. Chemical potential depends both on the mud's hydrostatic pressure in the wellbore and on its chemical composition.

To design an effective WBM, it is necessary to know the relative importance of mud differential pressure versus chemical concentration and composition, and how this relates to the type of mud and formation. For example, if the rock is chemically inert to WBM filtrate (as is the case with sandstone) then invasion is controlled solely by the differences between the wellbore pressure and the pore pressure within the rock. But for shale, opinion varies. Some experimenters suggest that the shale itself can act as a semipermeable membrane, making the chemical components the key determinant.

A number of relatively new types of mud systems have been introduced. For example, one route is to substitue the oil phase in OBM with synthetic chemicals. In this way, the excellent characteristics of OBM may be reproduced with a more rapidly biodegraded continous phase than was available before. 

 Typical synthetic base chemicals include esters, ethers, polyalphaolefins, linear olefins and linear akly benzenes. One of the chief disadvantages of these systems is that they tend to be relatively expensive compared to conventional OBM. However, such systems can still be cost-effective options compared to WBM. 


Wednesday, May 2, 2018

Designing and Managing Drilling Fluid

Gone are the days when drilling fluid - or mud as it is commonly called - comprised only clay and water. Today, the drilling engineer designing a mud program chooses from a comprehensive catalog of ingredients. The aim is to select an environmentally acceptable fluid that suits the well and the formation being drilled, to understand the mud's limitations, and then to manage operations efficiently within thoose limitations.

There are good reasons to improve drilling fluid performance and management, not least of which is economics. Mud may represents 5% to 15% of drilling costs but may cause 100% of drilling problems. Drilling fluids play sophisticated roles in the drilling process: stabilizing the wellbore without damaging the formation, keeping formation fluids at bay, clearing cuttings from the bit face, and lubricating the bit and drillstring, to name a few. High-angle wells, high temperatures and log, horizontal sections through pay zones make even more rigorous demands on drilling fluids.

Furthermore, increasing enviromental concerns have limited the use of some of the most effective drilling fluids and additives. At the same time, as part of the industry's drive for improved cost-effectiveness, drilling fluid performance has come under ever closer scrutiny.

This article looks at the factors influencing fluid choice, detailing two new types of mud. Then it will discuss fluid management during drilling.

What influences the choice of fluid?

Among the many factors to consider when choosing a drilling fluid are the well's design, anticipated formation pressures and rock mechanics, formation chemistry, the need to limit damage to the producing formation, temperature, environmental regulations, logistics, and economics.

To meet these design factors, drilling fluids offer a complex array of interrelated properties. Five basic properties are usually defined by the well program and monitored during drilling: rheology, density, fluid loss, solids content and chemical properties.

For any type of drilling fluid, all five properties may, to some extent, be manipulated using additives. However, the resulting chemical properties of a fluid depend largerly on the type of mud chosen. And this choice rests on the type of well, the nature of the formations to be drilled and the environmental circumstances of the well.

Issue & Decision

  • Specific healt and environmental concerns on type of mud and disposal of cuttings -> Determines mud system cuttings treatment/disposal strategy.
  • Remote location well -> May prevent the use of systems that consume large quantities of chemicals.
  • Composition and arrangement of the minerals in the formation and the clay chemistry -> Determines mud chemistry/ composition.
  •  Well profile/ angle -> Indicates the rheology needed to optimize hole cleaning. High-angle wells may need enhanced lubricity.
  • Strength and stress states versus hole angles -> Potential wellbore stability issues may concern mud weight. 
  •  Length of exposed open hole -> Greater inhibition needed for longer sections.
  •  Pore pressure -> Determines minimum mud weight needed to prevent blowout.
  • Rock strength-fracture gradient -> Indicates maximum mud weight that will not fracture well.
  • High -temperature well -> More than 275-300 degree F may cause product degradation.
  • Formation being drilled is pay zone -> Requires nondamaging mud to limit invasion, wettability effects of mud, potential emulsion blockage of the formation, fines mobilization and invasion, scale formation.

 Shales are the most common rock types encountered while drilling for oil and gas and give rise to more problems per meter drilled than any other type of formation. Estimates of worldwide, nonproductive cost associated with shale problems are put at $500 to $600 million anually. Common drilling problems like stuck pipe arise from hole closure and collapse, erosion and poor mud condition. In addition, the inferior wellbore quality often encountered in shales may make logging and completion operations difficult or impossible.



Wednesday, April 25, 2018

Corrosion in the Oil Industry

Most metals exist in nature as stable ores of oxides, carbonates or sulfides. Refining them, to make them useful, requires energy. Corrosion is simply nature's way of reversing an unnatural process back to a lower energy state. Preventing corrosion is vital in every step in the production of oil and gas. Corrosion cost US industries alone an estimated $170 billion a year. The oil industry, with its complex and demanding production techniques, and the environmental threat should components fail, takes an above average share of these costs.

Corrosion - the deterioration of a metal or its properties -attacks every component at every stage in the life of every oil and gas field. From casing strings to production platforms, from drilling through to abandonment, corrosion is an adversary worthy of all the high technology and research we can throw at it.

Oxygen, which plays such an important role in corrosion, is not normally present in producing formations. It is only at the drilling stage that oxgyen-contaminated fluids are first introduced. Drilling muds, left untreated, will corrode not only well casing, but also drilling equipment, pipelines and mud handling equipment. Water and carbon dioxide-produced or injected for secondary recovery-can cause severe corrosion of completion strings.  Acid-used to reduce formation damage around the well or to remove scale-readily attacks metal. Completions and surface pipelines can be eroded away by high production velocities or blasted by formation sand. Hydrogen sulfied [H2S] poses other problems. Handling all these corrosion situations, with the added complications of high temperatures, pressures and stresses involved in drilling or production, requires the expertise of a corrosion engineer, an increasingly key figure in the industry. 

Because it is almost impossible to prevent corrosion, it is becoming more apparent that controlling the corrosion reate may be the most economical solution. Corrosion engineers are therefore increasingly involved in estimating the cost of their solutions to corrosion prevention and estimating the useful life of equipment.  

Production wells were completed using 7-in. L-80 grade carbon steel tubing-an H2S-resistant steel-allowing flow rates in excess of 50 MMscf/D at over 150 degree celcius. High flow rates, H2S and carbon dioxide all contributed to the corrosion of the tubing. 

Mud corrosion-drilling mud also plays a key role in corrosion prevention. In addition to its well-known functions, mud must also remain noncorrosive. A greater awareness of corrosion problems has come about by the lower pH of polymer muds. Low pH means more acidic and hence more corrosive. Oil-base muds are usually noncorrosive and, before the introduction of polymer muds, water-base muds were used with relatively high pH of 10 or greater. So when polymer muds were introduced, corrosion from mud became more apparent.  

Completion design also plays an important role in preventing internal corrosion. Reducing sand production by gravel packing prevents sand blasting that causes  erosion corrosion. 

Stimulation programs may, inadvertently, promote internal corrosion. Depending on lithology, highly corrosive hydrochloric acid (HCl) with additions of hydrofluoric (HF) acid are used to improve near-wellbore permeability. These acids can also remove scale buildup on the inside of casing and tubing, allowing direct attack on bare metal.

Wednesday, April 11, 2018

3D Seismic Survey Design

There's more to designing a seismic survey than just choosing sources and receivers and shooting away. To get the best signal at the lowest cost, geophysicist are tapping an arsenal of technology from integration of borehole data to survey simulation in 3D.

The ideal 3D survey serves multiple purposes. Intially, the data may be used to enhance a structural interpretation based on two-dimensional (2D) data, yielding new drilling locations. Later in the life of a field, seismic data may be revisited to answer questions about fine-scale reservoir architecture or fluid contacts, or may be compared with a later monitor survey to infer fluid-front movement.All these stages of interpretation rely on satisfactory processing, which in turn relies on adequate seismic signal to process. The greatest processing in the world cannot fix flawed signal acquisition. 

Elements of a Good Signal

What makes a good seismic signal? Processing specialists list three vital requirements- good signal-to-noise ratio (S/N), high resolving power and adequate spatial coverage of the target. These basic elements form the foundation of survey design.

High S/N means the seismic trace has high amplitudes at times that correspond to reflections, and little or no amplitude at other times. During acquisition, high S/N is achieved by maximizing signal with a seismic source of sufficient power and directivity, and by minimizing noise. Noise can either be generated by the source - shot-generated or coherent noise, sometimes orders of magnitude stronger than deep seismic reflections - or be random. Limitations in the dynamic range of acquisition equipment require that shot-generated noise be minimized with proper source and receiver geometry. Proper geometry avoids spatial aliasing of the signal, attenuates noise and obtains signals that can benefit from subsequent processing. Aliasing is the ambiguity that arises when a signal is sampled less that twice per cycle. Noise and and signal cannot be distinguised when their sampling is aliased.

A common type of coherent noise that can be aliased comes from low-frequency waves trapped near the surface , called surface waves. On land, these are known as ground roll, and create major problems for processors. They pass the receivers at a much slower velocity than the signal, and so need closer receiver spacing to be properly sampled. Planners always try to design surveys so that surface waves do not contaminate the signal. But if this is not possible, the surface waves must be adequately sampled spatially so they can be removed. 

During processing, S/N is enhanced through filters that suppress noise. Coherent noise is reduced by removing temporal and spatial frequencies different from those of the desired signal, if known. Both coherent and random noise are suppressed by stacking - summing traces from a set of source-receiver pairs associated with reflections at a common midpoint, or CMP. The source-receiver spacing is called offset. To be stacked, every CMP set needs a wide and evenly sampled range of offsets to define the reflection travel time curve, known as normal moveout curve. Flattening that curve, called normal moveout correction, will make reflection from different offsets arrive at the time of the zero-offset reflection. They are then summed to produce a stack trace.

A 3D CMP trace is formed by stacking traces from source-receiver pairs whose midpoints share a more or less common position in a rectangular horizontal area defined during planning, called a bin. 

The number of traces stacked is called fold -in 24-fold data every stack trace represents the average of 24 traces. 

Many survey designers use rules of thumb and previous experience from 2D data to choose an optimal fold for certain targets or certain conditions. A fringe -called the fold taper or halo- around the edge of the survey will have partial fold, thus lower S/N, because several of the first and last shots do not reach as many receivers as in the central part of the survey. Getting full fold over the whole target means expanding the survey area beyond the dimensions of the target, sometimes by 100% or more. 

Many experts believe that 3D surveys do not require the level of fold of 2D surveys. This is because 3D processing correctly positions energy coming from outside the plane containing the source and receiver, which in the 2D case would be noise. The density of data in a 3D survey also permits the use of noise reduction processing, which performs better on 3D data than on 2D.

Filtering and stacking go a long way toward reducing noise, but one kind of noise that often remains is caused by multiple reflections, "multiples" for short. Multiples are particularly problematic where there is a high contrast in seismic properties near the surface. Typical multiples are reverberations within a low-velocity zone, such as between the sea surface and sea bottom, or between the earth's surface and the bottom of a layer of unconsolidated rock. Multiples can appear as later arrivals on a seismic section, and are easy to confuse with deep reflections. And because they can have the same charateristics as the desired signal-same frequency content and similiar velocities - they are often difficult to suppress through filtering and stacking. Sometimes they can be removed through other processing techniques, called demultiple processing.

The second characteristic of a good seismic signal is high resolution, or resolving power - the ability to detect reflectors and quantify the strength of the reflection. This is achieved by recording a high bandwidth, or wide range of frequencies. The greater the bandwidth, the greater the resolving power of the seismic wave. A common objective of seismic surveys is to distinguish the top and bottom of the target. The target thickness determines the minimum wavelength required in the survey, generally considered to be four times the thickness. That wavelength is used to calculate the maximum required frequency in the bandwidth -average seismic velocity to the target divided by minimum wavelength equals maximum frequency. 

The minimum frequency is related to the depth of the target. Lower frequencies  can travel deeper. Some seismic sources are designed to emit energy in particular frequency bands, and receivers normally operate over a wider band. Ideally, sources  that operate in the optimum frequency band are selected during survey design. More often, however surveys are shot with whatever equipment is proposed by the lowest bidder.

Another variable influencing resolution is source and receiver depth - on land, the depth of the hole containing the explosive source (receivers are usually on the surface), and at sea, how far below the surface the sources and receivers are towed.

The source-receiver geometry may produce short-path multiples between the sources, receivers, and the earth or sea surface. If the path of the multiple is short enough, the multiple-sometimes called a ghost- will closely trail the direct signal, affecting the signal's frequency content. The two-way travel time of the ghost is associated with a frequency, called the ghost notch, at which signals cancel out. This leaves the seismic record virtually devoid of signal amplitude at the notch frequency. The shorter the distance between the source or receiver and the reflector generating the multiple, the higher the notch frequency. It is important to choose a source and receiver depth that places the notch outside the desired bandwidth. 

On land, short-path multiples can reflect off near-surface layers, making deeper sources preferable. In marine surveys, waves add noise and instability, ncessitating deeper placement of both sources and receivers. 

The third requirement for good seismic data is adequate subsurface coverage. The lateral distance between CMPs at the target is the bin length. To record reflections from a dipping layer involves more distant sources and receivers than reflections from a flat layer, requiring expansion of the survey area-called migration aperture - to obtain full fold over the target.

Transition zones-shallow water areas- have their own problems, and require specialized equipment and creative planning. Transition zones are complex, involving shorelines, river mouths, coral reefs and swamps. They present a sensitive environment and are influenced by ship traffic, commercial fishing and bottom obstructions. Survey planners have to contend with varying water depths, high environmental noise, complex geology, wind, surf and multiple receiver types - often combination of hydrophones and geophones.  

Evaluation of existing data - 2D seismic lines and results from seismic source test - warned of potential problem areas. Source tests compared single-source dynamite shots to source patterns, and tested several source depths. The test indicated the presence of ghost notches at certain depths, leading to a reduction in signal energy within the desired frequency band of 10 to 60 Hz. The source test also indicated source patterns were ineffective in controlling ground roll in this prospect area. Deployment of the source at 9 m gave a good S/N ratio at 25 to 60 Hz, but produced very high levels of ground roll. Deployment of the source below 40 m gave a good S/N ratio from 10 to 60 hz and low levels of ground roll. However, such deep holes might be unacceptably time-consuming and costly.

Evaluation of existing 2D lines revealed the frequency content that could be expected from seismic data in the area. Evaluation of existing data indicated areas where special care had to be taken to ensure a successful survey. For example, high-velocity beds at the seafloor promised to cause strong multiples, reducing the energy transmitted to deeper layers and leading to strong reverbations in the water layer. 

 Evaluation of existing borehole data offered valuable insight into the transmission properties of the earth layers above the target and the gophysical parameters that could be obtained at the target. Comparison of formation tops inferred from acoustic impedance logs with reflection depths on the two VSPs allowed geophsyicist to differentiate real reflections from multiples. 


Wednesday, April 4, 2018

Saturation Monitoring With the RST Reservoir Saturation Tool

The RST Reservoir Saturation Tool combines the logging capabilities of traditional methods for evaluating saturation in a tool slim enough to pass through tubing. Now saturation measurements can be made without killing the well to pull tubing and regardless of the well's salinity.

Determining hydrocarbon and water saturations behind casing plays a major role in reservoir management. Saturation measurements over time are useful for tracking reservoir depletion, planning workover and enhanced recovery strategies , and diagnosing production problems such as water influx and injection water breakthrough.

Traditional methods of evaluating saturation - thermal decay time logging and carbon/oxygen (C/O) logging - are limited to high-salinity and nontubing wells, respectively. The RST Reservoir Saturation Tool overcomes these limitations by combining both methods in a tool slim enough to fit through tubing. The RST tool eliminates the need for killing the well and pulling tubing. This saves money, avoid reinvasion of perforated intervals, and allows the well to be observed under operating conditions. Moreover, it provides a log of the borehole oil fraction, or oil holdup, even in horizontal wells. 

To understand the operation and versatility of the RST tool requires an overview of existing saturation measurements and their physics.

The Saturation Blues

In a newly drilled well, openhole resistivity logs are used to determine water and hydrocarbon saturations. But once the hole is cased, saturation monitoring has to rely on tools such as the TDT Dual-Burst Thermal Decay Time tool or, for C/O logging, the GST Induced Gamma Ray Spectrometry Tool, which can "see" through casing.

The Dual-Burst TDT tool looks at the rate of thermal neutron absroption, described by the capture cross section gamma of the formation, to infer water saturation. A high absorption rate indicates saline water, which contains chlorine, a very efficient, abundant thermal-neutron absorber. A low absorption rate indicates fresh water or hydrocarbon.

The TDT technique provides good saturation measurements when formation water salinity is high, constant and known. But oil production from an increasing number of reservoirs is now maintained by water injection. This reduces or alters formation water salinity, posing a problem for the TDT tool. 

In low-salinity water (less than 35,000 parts per million), the tool cannot accurately differentiate between oil and water, which have similiar neutron capture cross sections.

When the salinity of the formation water is too low or unknown, C/O logging can be used. 
C/O logging measures gamma rays emitted from inelastic neutron scattering to determine relative concentrations of carbon and oxygen in the formation. A high C/O ratio indicates water or gas-bearing formations. 

The major drawback to C/O logging tools has been their large diameters. Producing wells must be killed and production tubing removed to accomodate tools with diameters of nearly 4 in. [10 cm] . In addition, the tools have slow logging speeds and are more sensitive to borehole fluid than formation fluid, which affects the precision of the saturation measurement.

As Easy as RST

The RST tool directly addresses these shortcomings and can perform either C/O or TDT logging. It comes in two diameters - 1 11/16 in. (RST-A) and 2 1/2 in. (RST-B) - and can be combined with other production logging tools. 

Both versions have two gamma ray detectors. In the RST-A tool, both detectors are on the tool axis, separated by neutron and gamma ray shielding. In the RST-B tool, the detectors are offset from the tool axis and shielded to enhance the near detector's borehole sensitivity and the far detector's formation sensitivity. This allows the formation oil saturation and borehole oil holdup to be derived from the same RST-B C/O measurement. 

Locating Bypassed Oil

In early 1992, ARCO drilled and perforated a sidetrack well in area of Prudhoe Bay undergoing waterflooding. Less than six months later, production was 90% water with less than 200 BOPD, as expected. The original perforations extended from X415 to X440 ft. C/O logging measurements were made in the shut-in well with three different tools - the RST tool and two sondes from other service companies.

The RST results confirmed depletion over the perforated interval (Tracks 2 and 3). Effects of the miscible gas flood sweep are apparent throughout the reservoir. The total inelastic count rate ratio of the near and far detectors indicates qualitatively the presenc of gas in the reservoir. In addition, differences between the openhole fluid analysis and the RST fluid analysis were assumed to be gas.

One potential bypassed zone, A, was identified from X280 to X290 ft. A second zone, B, based on the openhole logs and a C/O log from another service company, was proposed from X220 to X230 ft. The RST log shows zone B to contain more gas and water than zone A.

After assessing the openhole logs and the three C/O logs, ARCo decided to perforate zone B. The initial production was 1000 BOPD with a 75% water cut. Production declined to 200 BOPD with more than 95% water cut in a matter of weeks. The decline prompted ARCO to perforate zone A, commingling production from earlier perforations. Production increased to an average of 600 BOPD and the water cut decreased to 90%. Subsequent production logs confirm that zone A is producing oil and gas and zone B is producing all of the water with some oil.

Modes of Operation

Flexibility is a key advantage of the RST tool. It operates in three modes that can be changed in real time while logging:

  • inelasitc-capture mode
  • capture-sigma mode
  • sigma mode

Inelastic-capture mode: The inelastic-capture mode offers C/O measurements for determining saturations when the formation water salinity is unknown, varying or too low for TDT logging. In addition to C/O logging , thermal neutron capture gamma-ray spectra are recorded after the neutron burst. Elemental yields from these spectra provide lithology, porosity and apparent water salinity information.